The present invention relates generally to diamond enhanced inserts for use in drill bits and more particularly to diamond enhanced inserts for use in the gage or near-gage rows of rolling cone bits. Still more particularly, the present invention relates to placement of a diamond coating on an insert and to positioning the insert in a cone such that wear and breakage of the insert are reduced and the life of the bit is enhanced.
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied by the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole formed in the drilling process will have a diameter generally equal to the diameter or “gage” of the drill bit.
A typical earth-boring bit includes one or more rotatable cutters that perform their cutting function due to the rolling movement of the cutters acting against the formation material. The cutters roll and slide upon the bottom of the borehole as the bit is rotated, the cutters thereby engaging and disintegrating the formation material in its path. The rotatable cutters may be described as generally conical in shape and are therefore sometimes referred to as rolling cones. Such bits typically include a bit body with a plurality of journal segment legs. Each rolling cone is mounted on a bearing pin shaft that extends downwardly and inwardly from a journal segment leg. The borehole is formed as the gouging and scraping or crushing and chipping action of the rotary cones remove chips of formation material that are carried upward and out of the borehole by drilling fluid that is pumped downwardly through the drill pipe and out of the bit. The drilling fluid carries the chips and cuttings in a slurry as it flows up and out of the borehole. The earth disintegrating action of the rolling cone cutters is enhanced by providing the cutters with a plurality of cutter elements.
The cost of drilling a borehole is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits that will drill faster and longer and are usable over a wider range of formation hardnesses.
The length of time that a drill bit may be employed before it must be changed depends upon its rate of penetration (“ROP”), as well as its durability or ability to maintain an acceptable ROP. The form and positioning of the cutter elements on the cutters greatly impact bit durability and ROP and thus are critical to the success of a particular bit design.
Bit durability is, in part, measured by a bit's ability to “hold gage,” meaning its ability to maintain a full gage borehole diameter over the entire length of the borehole. Gage holding ability is particularly vital in directional drilling applications. If gage is not maintained at a relatively constant dimension, it becomes more difficult, and thus more costly, to insert drilling assemblies into the borehole than if the borehole had a constant full gage diameter. For example, when a new, unworn bit is inserted into an undergage borehole, the new bit will be required to ream the undergage hole as it progresses toward the bottom of the borehole. Thus, by the time it reaches the bottom, the bit may have experienced a substantial amount of wear that it would not have experienced had the prior bit been able to maintain full gage. This unnecessary wear will shorten the bit life of the newly-inserted bit, thus prematurely requiring the time-consuming and expensive process of removing the drill string, replacing the worn bit, and reinstalling another new bit downhole.
Cutter elements are generally of two types: inserts formed of a very hard material, such as tungsten carbide, that are press fit into undersized apertures in the cone surface; or teeth that are milled, cast or otherwise integrally formed from the material of the rolling cone. Bits having tungsten carbide inserts are typically referred to as “TCI” bits, while those having teeth formed from the cone material are known as “milled tooth bits.” In each case, the cutter elements on the rotating cutters functionally breakup the formation to form new borehole by a combination of gouging and scraping or chipping and crushing. While the present invention has primary application in bits having inserts rather than milled teeth and the following disclosure is given in terms of inserts, it will be understood that the concepts disclosed herein can also be used advantageously in milled tooth bits.
To assist in maintaining the gage of a borehole, conventional rolling cone bits typically employ a heel row of hard metal inserts on the heel surface of the rolling cone cutters. The heel surface is a generally frustoconical surface and is configured and positioned so as to generally align with and ream the sidewall of the borehole as the bit rotates. The inserts in the heel surface contact the borehole wall with a sliding motion and thus generally may be described as scraping or reaming the borehole sidewall. The heel inserts function primarily to maintain a constant gage and secondarily to prevent the erosion and abrasion of the heel surface of the rolling cone. Excessive wear of the heel inserts leads to an undergage borehole, decreased ROP, increased loading on the other cutter elements on the bit, and may accelerate wear of the cutter bearing and ultimately lead to bit failure.
In addition to the heel row inserts, conventional bits typically include a gage row of cutter elements mounted adjacent to the heel surface but orientated and sized in such a manner so as to cut the corner of the borehole. In this orientation, the gage cutter elements generally are required to cut both the borehole bottom and sidewall. The lower surface of the gage row insert engages the borehole bottom while the radially outermost surface scrapes the sidewall of the borehole. Conventional bits also include a number of additional rows of cutter elements that are located on the cones in rows disposed radially inward from the gage row. These cutter elements are sized and configured for cutting the bottom of the borehole and are typically described as inner row cutter elements.
Differing forces are applied to the cutter elements by the sidewall than the borehole bottom. Thus, requiring gage cutter elements to cut both portions of the borehole compromises the cutter design. In general, the cutting action operating on the borehole bottom is typically a crushing or gouging action, while the cutting action operating on the sidewall is a scraping or reaming action. Ideally, a crushing or gouging action requires a tough insert, one able to withstand high impacts and compressive loading, while the scraping or reaming action calls for a very hard and wear resistant insert. One grade of cemented tungsten carbide cannot optimally perform both of these cutting functions as it cannot be as hard as desired for cutting the sidewall and, at the same time, as tough as desired for cutting the borehole bottom. Similarly, PCD grades differ in hardness and toughness and, although PCD coatings are extremely resistant to wear, they are particularly vulnerable to damage caused by impact loading as typically encountered in bottom hole cutting duty. As a result, compromises have been made in conventional bits such that the gage row cutter elements are not as tough as the inner row of cutter elements because they must, at the same time, be harder, more wear resistant and less aggressively shaped so as to accommodate the scraping action on the sidewall of the borehole.
In FIG. 14 the positions of all of the cutter inserts from all three cones are shown rotated into a single plane. As shown in FIG. 14, to assist in maintaining the gage of a borehole, conventional rolling cone bits typically employ a row of heel cutters 214 on the heel surface 216 of each rolling cone 212. The heel surface 216 is generally frustoconical and is configured and positioned so as to generally align with the sidewall of the borehole as the bit rotates. The heel cutters 214 contact the borehole wall with a sliding motion and thus generally may be described as scraping or reaming the borehole sidewall. The heel cutters 214 function primarily to maintain a constant gage and secondarily to prevent the erosion and abrasion of the heel surface of the rolling cone.
In addition to heel row cutter elements, conventional bits typically include a row of gage cutter elements 230 mounted in gage surface 231 and oriented and sized in such a manner so as to cut the corner of the borehole. For purposes of the following discussion, the gage row is defined as the first row of inserts from the bit axis of a multiple cone bit that cuts to full gage. This insert typically cuts both the sidewall of the borehole and a portion of the borehole floor. Cutting the corner of the borehole entails cutting both a portion of the borehole side wall and a portion of the borehole floor. It is also known to accomplish the corner cutting duty that is usually performed by the gage cutters by dividing it between adjacent gage and nestled gage cutters (not shown) such that the nestled gage cutters perform most of the sidewall cutting and the adjacent gage cutters cut the bottom portion of the corner.
Conventional bits also include a number of additional rows of cutter elements 232 that are located on the main, generally conical surface of each cone in rows disposed radially inward from the gage row. These inner row cutter elements 232 are sized and configured for cutting the bottom of the borehole and are typically described as inner row cutter elements.
In FIGS. 14, 16, 18 20 and 22, the positions of all of the cutter inserts from all three cones are shown rotated into a single plane. As can be seen, the cutter elements in the heel and gage rows typically share a common position across all three cones, while the cutter elements in the inner rows are radially spaced so as to cut the borehole floor in the desired manner. Excessive or disproportionate wear on any of the cutter elements can lead to an undergage borehole, decreased-ROP, or increased loading on the other cutter elements on the bit, and may accelerate wear of the cutter bearing and ultimately lead to bit failure.
Relative to polycrystalline diamond, tungsten carbide inserts are very tough and impact resistant, but are vulnerable to wear. Thus, it is known to apply a cap layer of polycrystalline diamond (PCD) to each insert. The PCD layer is extremely wear-resistant and thus improves the life of a tungsten carbide insert. Conventional processing techniques have, however, limited the use of PCD coatings to axisymmetrical applications. For example, a common configuration for PCD coated inserts can be seen in FIGS. 14 and 15, wherein insert 230 comprises a domed tungsten carbide base or substrate 240 supporting a hemispherical PCD coating 242. Inserts of this type are formed by forming a non-reactive container also known as a “can”, corresponding to the external shape of the insert, positioning a desired amount of PCD powder in the can, placing the substrate in the can on top of the PCD powder, enclosing and sealing the can, and applying sufficient pressure and temperature to sinter the PCD and adhere it to the substrate. If required, the resulting diamond or substrate layers can be ground into a final shape following demolding.
The shape of PCD layers formed in this manner is based on consideration of several factors. First, the difference in the coefficients of thermal expansion of diamond and tungsten carbide gives rise to differing rates of contraction as the sintered insert cools. This in turn causes residual stresses to exist in the cooled insert at the interface between the substrate and the diamond layer. If the diamond layer is too thick, these residual stresses can be sufficient to cause the diamond layer to break away from the substrate even before any load is applied. On the other hand, if the diamond layer is too thin, it may not withstand repetitive loading during operation and may fail due to fatigue. The edge 261 of the diamond coating is a particular source of stress risers and is particularly prone to failure.
For all of these reasons, PCD coated inserts have typically been manufactured with a hemispherical top, commonly referred to as a “semi-round top” or SRT. Referring again to FIG. 15, the SRT 303 is aligned with the longitudinal axis 241 of the substrate such that its center point lies approximately on axis 241. The inner surface of the diamond coating corresponds to the domed shape of the substrate. Thus, the thickness of the diamond coating is greatest on the axis of the insert and decreases toward the edge of the coating layer. While inserts in which the diamond coating is of uniform thickness are known, e.g. U.S. Pat. No. 5,030,250, it is more common to form a diamond layer that decreases in thickness as distance from the center point increases, resulting in the crescent-shaped cross-section shown in FIG. 15. Nevertheless, it is contemplated that diamond layer 242 can be other than crescent-shaped. For example, the thickest portion of diamond layer 242 could comprise a region rather than a point. The diamond layer typically tapers toward the outer diameter of the substrate (the diamond edge 261). This tapering helps prevent cracks that have been known to develop at the diamond edge when a substantially uniform diamond layer is used.
Because of the interrelationship between the shape of each cone and the shape of the borehole wall, cutter elements in the heel row and inner rows are typically positioned such that the longitudinal axes of those cutter elements are more or less perpendicular to the segment of the borehole wall (or floor) that is engaged by that cutter element at the moment of engagement. In contrast, cutter elements in the gage row do not typically have such a perpendicular orientation. This is because in prior art bits, the gage row cutter elements are mounted so that their axes are substantially perpendicular to the cone axis 213. Mounted in this manner, each gage cutter element engages the gage curve 222 at a contact point 243 (FIG. 15) that is close to the thin edge of the diamond coating on the hemispherical top of each cutter element.
Still referring to FIG. 15, the angle between the insert axis 241 and a radius terminating at contact point 243 is hereinafter designated a. In prior art bits, the angle α has typically been in the range of 54° to 75°, with a being greater for harder formation types. For example, in a typical 12¼″ rock bit, α may be about 57°.
The prior art configuration described above is not satisfactory, however, because contact point 243 is at the edge of diamond layer 242, where the diamond layer is relatively thin, and is subjected to particularly high stresses and is therefore especially vulnerable to cracking and breaking, which in turn leads to premature failure of the inserts in the gage row.
Accordingly, there remains a need in the art for a gage insert that is more durable than those conventionally known and that will yield greater ROP's and an increase in footage drilled while maintaining a full gage borehole. Preferably, the gage insert would also be relatively simple to manufacture.